Monovalent Brine-Based Reservoir Drilling Fluid

ABSTRACT

Wellbore fluids may contain an aqueous base fluid comprising a monovalent brine, a modified starch, and a metal oxide. Methods of using wellbore fluids may include drilling a subterranean well while circulating a wellbore fluid into the subterranean well, wherein the wellbore fluid contains an aqueous base fluid comprising a monovalent brine, a modified starch, and a metal oxide.

CROSS-REFERENCE TO RELATED APPLICATION

The present document is based on and claims priority to U.S. ProvisionalApplication Ser. No. 62/189,990, filed Jul. 8, 2015, which isincorporated herein by reference in its entirety.

BACKGROUND

During the drilling of a wellbore, various fluids are typically used inthe well for a variety of functions. The fluids may be circulatedthrough a drill pipe and drill bit into the wellbore, and then maysubsequently flow upward through the wellbore to the surface. Duringthis circulation, a drilling fluid may act to remove drill cuttings fromthe bottom of the hole to the surface, to suspend cuttings and weightingmaterial when circulation is interrupted, to control subsurfacepressures, to maintain the integrity of the wellbore until the wellsection is cased and cemented, to isolate the fluids from the formationby providing sufficient hydrostatic pressure to prevent the ingress offormation fluids into the wellbore, to cool and lubricate the drillstring and bit, and/or to maximize penetration rate.

Other wellbore fluids include completion fluids used in the wellborefollowing drilling operations. Completion fluids broadly refer any fluidpumped down a well after drilling operations have been completed,including fluids introduced during acidizing, perforating, fracturing,workover operations, etc. For example, reservoir drill-in fluid (RDF) isa specific type of completion fluid that is designed to drill andcomplete the reservoir section of a well in an open hole that isresponsible for hydrocarbon production. RDF fluids may protect theformation from damage and fluid loss, while remaining removable whenexposed to breaker fluids to minimize impediments to future production.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one aspect, embodiments disclosed herein relate to wellbore fluidsthat include at least an aqueous base fluid with a monovalent brine, amodified starch, and a metal oxide.

In another aspect, embodiments disclosed herein relate to methods ofdrilling a subterranean well that include at least drilling thesubterranean well while circulating a wellbore fluid in the subterraneanwell, where the wellbore fluid includes at least an aqueous base fluidand a modified starch, where the aqueous base fluid includes at least amonovalent brine.

In another aspect, embodiments disclosed herein relate to a method ofreducing the loss of fluid out of a subterranean well, where the methodincludes at least injecting into the subterranean well a wellbore fluid,where the wellbore fluid includes at least an aqueous base fluidcontaining a monovalent brine; a modified starch; and a metal oxide.

In another aspect, embodiments disclosed herein relate to a method ofcompleting a wellbore, where the method includes at least drilling thewellbore with a wellbore fluid to form a filter cake on the walls of thewellbore, emplacing a breaker fluid into the wellbore, and shutting inthe well for a period of time sufficient to initiate breaking of thefilter cake. In such aspects, the wellbore fluid includes at least anaqueous base fluid containing a monovalent brine; and a modified starch.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to wellbore fluidsformulated from monovalent brines while maintaining favorable lowhigh-end rheology and high low-end rheology and ease of filter cakecleanup using any of acids, chelating agents, and oxidizers. Further,wellbore fluids in accordance with the present disclosure may generate alow viscosity fluid with fluid loss control properties that may reducethe need for divalent brines often added to increase density andsuspension properties.

During drilling, a filter cake may build up as particles and materialsof varying sizes and types from wellbore fluids are deposited andaccumulate on the walls of the borehole. Prior to production, the filtercake may be removed to some degree, either physically or chemicallyusing breaker fluids that may contain acids, oxidizers, and/or enzymes,for example. However, additives used in standard drilling fluids such asweighting solids and polymeric fluid loss materials may be resistant todegradation and conventional breaker fluids leaving residues that mayhinder efficient hydrocarbon production, particularly when drillingfluid residues are present in producing intervals.

In order to overcome the problems of formation damage associated withstandard drilling fluids, a specialty fluid having a limited amount ofsolids and often degradable polymeric additives known as a reservoirdrill-in fluid (RDF) may be used when drilling through the reservoirsection of a wellbore. Particularly, RDFs may be formulated to minimizedamage and maximize production of exposed zones. In some respects, anRDF may resemble a completion fluid. For example, drill-in fluids may bebrines containing only selected solids of appropriate particle sizeranges (often removable salts such as calcium carbonate) and fluid lossadditives. Because completeness of removal and maximization ofproduction of hydrocarbons can be significant weighting factors, it maybe desirable in some embodiments to limit the inclusion of additivesinto the drill-in fluid to those essential for filtration control andremoval of cuttings from the wellbore.

While divalent brines are often used to formulate wellbore fluids,including

RDFs, divalent species present in the brines are known to cause scalingand impact subsequent cleaning and removal operations negatively, oftenby forming poorly soluble carbonate and sulfate scales. Compounding thesituation, when drilling through formation intervals, connate waters maybe released from the surrounding rock. Connate waters often containvarying concentrations of native divalent species cations, includingalkaline or alkali metals such as calcium and magnesium, or species thatmay form insoluble complexes when mixed with injected wellbore fluids.In some cases, the mixture of native water with wellbore fluids maycause adverse changes in the wellbore fluid composition such asprecipitation of components of the wellbore fluid, changes in fluiddensity, pH variances, etc.

In one or more embodiments, wellbore fluids in accordance with thepresent disclosure may be formulated from a monovalent brine and minimalor no divalent ions to increase the compatibility of injected wellborefluids with formation fluids and minimize adverse interactions such asthe production of insoluble scales and other precipitates. Decreasedreliance of divalent brines may also aid completions and cleanupoperations by allowing the use of breaker fluids that incorporatechelating agents or other breakers that are negatively impacted by thepresence of divalent ions.

In order to facilitate removal of filter cakes prior to productionoperations, wellbore fluids in accordance with the present disclosuremay also be formulated without incorporating biopolymer viscosifiersthat may otherwise contribute to formation damage and decreasedproduction. Biopolymers are often incorporated in drilling fluids,particularly fluids formulated with monovalent brines, in order toimpart favorable rheological characteristics, in addition to increasingthe stability of the drilling fluid at elevated temperatures. However,the increased viscosity and durability of biopolymer additives alsointroduces added challenges in removing such additives prior toproduction because standard breaker fluids are often unable to removeenough of the generated filter cakes to allow sufficient productionlevels.

As used herein, the term “biopolymer viscosifier” is intended to mean anextracellular polysaccharide of high molecular weight, such as in excessof 500,000 Da, produced by fermentation of a carbohydrate source by theaction of bacteria or fungi. Representative microorganisms may includethe genus Xanthomonas, Pseudomonas, Agrobacterium, Arthrobacter,Rhizobium, Alcaligenes, Beijerincka, and Sclerotium. Biopolymers thatare often incorporated into wellbore fluids, but that may be excludedfrom the present fluids, include xanthan gum, welan gum, gellan gum,schleroglucan gum, succinoglycan gum, and the like.

Instead, wellbore fluids of the present disclosure may incorporate amodified starch additive that provides ample rheological, fluid loss,and clean-up properties needed to function as an RDF. Further, while itis commonly believed that divalent brines are required in the absence ofbiopolymer viscosifiers in order to obtain a drilling fluid havingsufficient viscosity and suspension properties, inventors of the presentdisclosure have discovered that wellbore fluids may be formulated in amonovalent brine base fluid when modified starch additives aresupplemented with limited concentrations of metal oxides. Thus, an RDFmay be formulated such that it remains compatible when mixed withformation fluids containing divalent salts, yet retains favorablerheological characteristics, including suspension of drill cuttings andinsoluble fluid components, in a monovalent brine. The metal oxides arepresent in a limited quantity as compared to the concentration ofdivalent species generally present in a divalent brine (i.e., by atleast an order of magnitude smaller). For example, in one or moreembodiments, the wellbore fluid of the present disclosure may have nomore than 5 percent by weight of the fluid (wt %) (or no more than 2 to3 wt % in other embodiments) of an alkaline earth metal (in any form,such as a salt, metal oxide, etc.).

While the fluids of the present disclosure may be particularly suitablefor use in drilling a producing interval of a wellbore, one skilled inthe art would appreciate that no limitation on the scope of the presentdisclosure exists, and wellbore fluids of the present disclosure may beused to drill within a wellbore irrespective of whether drilled intervalcorresponds to the producing region. Further, wellbore fluids inaccordance with the present disclosure may have utility in reducing thescaling attributed to divalent species in completions, displacement,hydraulic fracturing, work-over, under-reaming, packer fluid emplacementor maintenance, well treating, or testing operations.

In one or more embodiments, RDFs in accordance with the presentdisclosure may include a monovalent base fluid, a modified starch, and ametal oxide. In some embodiments, wellbore fluids may be formulated witha density of up to 13.5 pounds per gallon (ppg) or greater. In otherembodiments, the density of the final wellbore fluid may be within therange of 8.5 ppg to 13.5 ppg.

Monovalent Brines

In one or more embodiments, monovalent brines of the present disclosuremay be selected from brines such as, but not limited to, ammoniumchloride, lithium bromide, lithium chloride, lithium nitrate, sodiumbromide, sodium chloride, sodium nitrate, potassium chloride, potassiumbromide, potassium nitrate, cesium nitrate, cesium chloride, cesiumbromide, and the like. Other possible monovalent brines include formatesalts such as cesium, potassium, and/or sodium.

The monovalent brine may be included in the wellbore fluids in an amountenough to achieve a suitable density for use in well-drillingoperations. In some embodiments, the density of the monovalent brine inpounds per gallon (ppg) may range from a lower limit of greater than 3ppg, 5 ppg, 7 ppg, 9 ppg to an upper limit of less than 11 ppg, 13 ppg,15 ppg, 17 ppg, 19 ppg, where the density may range from any lower limitto any upper limit. However, one skilled in the art would appreciatethat the amount may vary depending on the density of the wellbore fluiddesired for a particular application.

Modified Starch

Wellbore fluids in accordance with the present disclosure may include amodified starch to impart fluid loss control properties, including atelevated temperatures. Starch is a natural polymer formed fromanhydroglucose that may contain a number of free secondary hydroxyls andprimary hydroxyls. These hydroxyls potentially are able to react withany chemical capable of reacting with alcoholic hydroxyls. This mayinclude a wide range of compounds such as acid anhydrides, organichalogenated compounds, aldehydes, epoxy, olefins, etc.

Modified starches in accordance with the present disclosure may includechemically modified starches, including starch treated with a number ofmulti-functional crosslinking agents. Crosslinking agents may containtwo or more moieties capable of reacting with hydroxyl groups present onthe same molecule or on different molecules. Crosslinking agents mayinclude, for example, epihalohydrins, formaldehyde, phosphorousoxychloride, trimetaphosphates, adipic-acetic anhydrides, dialdehydes,vinyl sulfone, diepoxides, diisocyanates, bis(hydroxymethyl) ethyleneurea, and the like. Further, one skilled in the art would appreciatethat the base material for crosslinking may be a chemically modifiedstarch, such as a starch having a portion of its hydroxyl groupsreplaced by either ester or ether groups. For example, a portion of thehydroxyl groups may be etherified with propylene oxide to form ahydroxypropyl starch or etherified with monochloracetic acid to form acarboxymethyl starch; however, alkoxylated starches or starch esterssuch as starch acetates may also be used.

Selection between esterified/etherified starch and/or crosslinked starchmay, for example, be dependent on the particular wellbore operation andformation in which the fluid is being used. For example, one skilled inthe art would appreciate that depending on the expected temperatures acrosslinked starch may provide additional thermal stability to thefluid.

In one or more embodiments, modified starches include starches derivedfrom any plant source such as corn, wheat, rice, tapioca, sago, waxymaize, waxy rice, sorghum, potato, pea, roots containing a high starchcontent, etc. Starch consists of linked anhydro-D-glucose units havingeither a mainly linear structure (amylose) or a branched structure(amylopectin). However, one skilled in the art would appreciate that asingle plant species may exist with certain proportions of amylose andamylopectin, and that hybrids with varying proportions may also exist.Further, it is known that “starch” may also refer to common starch,which contains both amylose and amylopectin molecules, oramylopectin-based starches such as waxy starch. In some embodiments, thestarch additive may be a commercially available additive such as DITROLavailable from M-I, L.L.C.

Modified starches in accordance with the present disclosure may be addedto a wellbore fluid at a concentration that ranges from 1 to 20 poundsof modified starch per barrel (ppb) in some embodiments, and from 3 to18 ppb in other embodiments. However, the effective amount of modifiedstarch may vary depending on the other components of the wellbore fluid,as well as the characteristics and conditions of the formation in whichit is employed.

Metal Oxides

Wellbore fluids in accordance with the present disclosure may includeone or more metal oxides that may impart favorable rheology on thewellbore fluid by interacting with the modified starch and/or modifyingand buffering the pH of the wellbore fluid. For example, a metal oxidesuch as MgO, may participate in crosslinking reactions with a modifiedstarch that increases the viscosity of the wellbore fluid, in additionto increasing the pH of the wellbore fluid. Metal oxides may includedivalent metal oxides such as cupric oxide, magnesium oxide, and calciumoxide, iron oxide, and zinc oxide. In some embodiments, metal oxides maybe of the formula MO where M represents a divalent metal of one of thePeriodic Table Groups 2, 8, 9, 10, 11 and 12 and mixtures thereof.

In one or more embodiments, the reactivity of the metal oxide may beincreased by increasing the surface area of the oxide through grindingor milling to produce a powder or dust. For example, one suitable formof magnesium oxide is a very fine powder is a highly reactive form,i.e., having small particle size, high surface area, and readyaccessibility for reaction. One example of such a fine powder magnesiumoxide is available commercially from M-I LLC under the trade name ofDIBALANCE™.

Wellbore fluids in accordance with the present disclosure may contain aconcentration of a metal oxide that may range from 0.5 ppb to 10 ppb insome embodiments, from 1 ppb to 8 ppb or 2 ppb to 5 ppb in otherembodiments.

Other Wellbore Fluid Additives

Other additives for use in wellbore fluids may include for example,fluid loss control agents, mutual solvents, wetting agents, organophilicclays, viscosifiers, surfactants, dispersants, interfacial tensionreducers, mutual solvents, thinners, thinning agents and cleaningagents. The addition of such agents should be well known to one ofordinary skill in the art of formulating drilling fluids and muds.

In one or more embodiments, an amine stabilizer may be used as a pHbuffer and/or thermal extender to prevent acid-catalyzed degradation ofpolymers present in the fluid. A suitable amine stabilizer may includetriethanolamine; however, one skilled in the art would appreciate thatother amine stabilizers such as methyldiethanol amine (MDEA),dimethylethanol amine (DMEA), diethanol amine (DEA), monoethanol amine(MEA), cyclic organic amines, sterically hindered amines, amides offatty acid, or other suitable tertiary, secondary, and primary aminesand ammonia could be used in the fluids of the present disclosure.

In some embodiments, the amine stabilizer may be commercially availableamine stabilizers such as PTS-200, or polyether amines polyether aminessuch as the JEFFAMINE series of polyether amines including JeffamineD-230, all of which are available from M-I L.L.C. (Houston, Tex.). Aminestabilizers may be added to a wellbore fluid in accordance with thepresent disclosure at a concentration that ranges from 0.1% to 10% byweight of the wellbore fluid in some embodiments, and from 0.5% to 5% byweight of the wellbore fluid in other embodiments.

If necessary, the density of the fluid may be increased by incorporationof at least one solid material, such as a bridging agent or weightingagent, may be included in the wellbore fluids of the present disclosure.Bridging particles, weighting agents or density materials suitable foruse in some embodiments include galena, hematite, magnetite, ironoxides, illmenite, barite, siderite, celestite, dolomite, calciumcarbonate, silica, and the like. Alternatively, such materials may alsoinclude fibrous cellulosic materials, graphite, coke, perlite, etc. Thequantity of such material added, if any, depends upon the desireddensity of the final composition. Typically, weight material is added toresult in a drilling fluid density of up to about 24 pounds per gallon(ppg). The weight material may be added up to 21 ppg and, in otherembodiments, up to 19.5 ppg. In one embodiment, calcium carbonate may beused as a bridging agent in forming a filter cake.

Breaker Fluids

Further, a breaker fluid may be emplaced in a wellbore drilled with thefluids of the present disclosure when clean-up/removal of a filter cakeis desired. The breaker may be selectively emplaced in the wellbore, forexample, by spotting the fluid through a coil tube or by bullheading.However, no limitation on the techniques by which the breaker fluid ofthe present disclosure is emplaced is intended on the scope of thepresent application. After a period of time sufficient, i.e., severalhours to several days, to allow for disruption or fragmentation of thefilter cake and the fluid may be returned to the surface for collectionand subsequent recovery techniques. Subsequent washes of the wellborewith wash fluids may be desirable to ensure complete removal of filtercake material remaining therein. Various types of breakers are known inthe art, and no limitation is intended on the type of breaker(s) thatmay be used to disrupt filter cakes formed from wellbore fluids of thepresent disclosure. Rather, it is envisioned that any of enzyme,solvent, chelant, acidizing, or oxidizing breakers may be used inbreaking such filter cakes. In a particular embodiment, it may bedesirable to include an enzyme/solvent/acid breaker combination forbreaking the crosslinked starch, viscosified surfactant, and bridgingsolids.

The breaker fluids of the present disclosure may also be formulated tocontain an acid source to decrease the pH of the breaker fluid and aidin the degradation of filter cakes within the wellbore. Examples of acidsources that may be used as breaker fluid additives include strongmineral acids, such as hydrochloric acid or sulfuric acid, and organicacids, such as citric acid, salicylic acid, lactic acid, malic acid,acetic acid, and formic acid. Suitable organic acids that may be used asthe acid sources may include citric acid, salicylic acid, glycolic acid,malic acid, maleic acid, fumaric acid, and homo- or copolymers of lacticacid and glycolic acid as well as compounds containing hydroxy, phenoxy,carboxylic, hydroxycarboxylic or phenoxycarboxylic moieties.

Alternatively, a delayed acid source may be used which reduces the pH ofthe wellbore fluid over a period of time. In particular, compounds thathydrolyze to form acids in situ may be utilized. Such delayed source ofacidity may be provided, for example, by hydrolysis of an ester oramide. It is well known in the art that temperature, as well as thepresence of hydroxide ion source, has a substantial impact on the rateof hydrolysis of esters. For a given acid, such as formic acid, forexample, one of skill in the art can conduct simple studies to determinethe time to hydrolysis at a given temperature. It is also known that asthe length of the alcohol portion of the ester increases, the rate ofhydrolysis decreases. Thus, by systematically varying the length andbranching of the alcohol portion of the ester, the rate of release ofacid may be controlled, and thus the setting of the wellbore fluid maybe predetermined.

Illustrative examples of such delayed acid sources include hydrolyzableanhydrides of carboxylic acids, hydrolyzable esters of carboxylic acids,hydrolyzable esters of phosphonic acid, and hydrolyzable esters ofsulfonic acid. Breaker fluids in accordance with this disclosure mayinclude delayed acid sources such as, for example, R¹H₂PO₃, R¹R²HPO₃,R¹R²R³PO₃, R¹HSO₃, R¹R²SO₃, R¹H₂PO₄, R¹R²HPO₄, R¹R²R³PO₄, R¹HSO₄, orR¹R²SO₄, where R¹, R², and R³ are C₂ to C₃₀ alkyl-, aryl-, arylalkyl-,or alkylaryl-groups.

Suitable esters may include carboxylic acid esters so that the time toachieve hydrolysis is predetermined on the known downhole conditions,such as temperature and pH. In a particular embodiment, the delayed acidsource may include a formic or acetic acid ester of a C2-C30 alcohol,which may be mono- or polyhydric, such as ethylene glycol monoformate ordiformate. Other esters that may find use in activating the internalbreaker of the present disclosure include those releasing C1-C6carboxylic acids, including hydroxycarboxylic acids formed by thehydrolysis of lactones, such as γ-lactone and δ-lactone). In anotherembodiment, a hydrolyzable ester of C1 to C6 carboxylic acid and a C2 toC30 poly alcohol, including alkyl orthoesters, may be used. In someembodiments, the delayed acid source may be the hydrolysable esterD-STRUCTOR™ available from M-I L.L.C. (Houston, Tex.).

Breaker fluids in accordance with the present disclosure may alsoincorporate one or more chelating agents. Chelating agents sequesterpolyvalent cations through bonds to two or more atoms of the chelatingagent. Chelating agents may act to remove structural components from thefilter cake, weakening the overall structure and aiding in filter cakeremoval. For example, cations sequestered by the chelants may be sourcedfrom solid filter cake components including various weighting orbridging agents such as calcium carbonate, barium sulfate, etc. Usefulchelating agents may include organic ligands such as ethylenediamine,diaminopropane, diaminobutane, diethylenetriamine,triethylenetetraamine, tetraethylenepentamine, pentaethylenehexamine,tris(aminoethyl)amine, triaminopropane, diaminoaminoethylpropane,diaminomethylpropane, diaminodimethylbutane, bipyridine, dipyridylamine,phenanthroline, aminoethylpyridine, terpyridine, biguanide and pyridinealdazine.

Chelating agents suitable for use in the breaker fluids of the presentdisclosure may include polydentate chelating agents such asethylenediaminetetraacetic acid (EDTA), diethylenetriaminepentaaceticacid (DTPA), nitrilotriacetic acid (NTA), ethyleneglycol-bis(2-aminoethyl)-N,N,N′,N′-tetraacetic acid (EGTA) ,1,2-bis(o-aminophenoxy)ethane-N,N,N′,N′-tetraaceticacid (BAPTA),cyclohexanediaminete-traacetic acid (CDTA),triethylenetetraaminehexaacetic acid (TTHA),N-(2-Hydroxyethyl)ethylenediamine-N,N′,N′-triacetic acid (HEDTA),glutamic-N,N-diacetic acid (GLDA), ethylene-diamine tetra-methylenesulfonic acid (EDTMS), diethylene-triamine penta-methylene sulfonic acid(DETPMS), amino tri-methylene sulfonic acid (ATMS), ethylene-diaminetetra-methylene phosphonic acid (EDTMP), diethylene-triaminepenta-methylene phosphonic acid (DETPMP), amino tri-methylene phosphonicacid (ATMP), and mixtures thereof. Such chelating agents may includepotassium or sodium salts thereof in some embodiments. However, thislist is not intended to have any limitation on the chelating agents (orsalt types) suitable for use in the embodiments disclosed herein.

EXAMPLES Example 1 Rheological Properties of Monovalent RDF Formulations

In the following example, the rheological characteristics of monovalentRDF formulations where compared to an equivalent divalent brine-basedRDF. Wellbore fluids were prepared by combining the fluid components asshown below in Table 1 for monovalent RDF, and Table 3 for thecomparative divalent formulation, taking into account samples of variousmetal oxides; a phosphonic acid scale inhibitor; a chemically modifiedstarch; and a calcium carbonate weighting agent; all of which arecommercially available from M-I L.L.C.

Results from the rheological measurements are shown in Tables 2 and 4for the monovalent and divalent RDFs, respectively. As demonstrated, themonovalent formulations have similar rheological profiles and densitiesto RDFs formulated using a divalent base brine.

TABLE 1 Divalent RDF Formulations C1 C2 C3 C4 Density (ppg) 9.5 9.5 10.310.3 Brine Type CaCl₂ CaBr₂ CaCl₂ CaBr₂ Base Brine Density (ppg) 8.688.68 9.54 9.54 Components (ppb) 11.6 CaCl₂ 48.0 — 167.0 — 14.2 CaBr₂ —31.0 — 113.0 water 292.0 304.0 206.0 256.0 modified starch 10.0 10.010.0 10.0 metal oxide #1 2.0 2.0 2.0 2.0 metal oxide #2 2.0 2.0 0.500.50 metal oxide #2 4.0 4.0 2.0 2.0 sized CaCO₃ 45.0 45.0 45.0 45.0

TABLE 2 Rheological Properties of Divalent brine-based RDFs Sample No.C1 C2 C3 C4 Aging Time Initial 16 h Initial 16 h Initial 16 h Initial 16h Aging Temp. (° F.) 180 Aging Mode Dynamic Dynamic Dynamic DynamicMeasurement Temp. (° F.) 120 600 RPM 39 45 42 42 52 57 49 50 300 RPM 3032 32 29 36 40 34 35 200 RPM 28 26 27 23 30 33 28 29 100 RPM 23 20 22 1620 24 20 20  6 RPM 8 9 6 6 9 9 6 7  3 RPM 7 8 5 5 8 8 5 6 Gel 10 Sec(lb/100 ft²) 9 10 7 7 9 8 6 7 Gel 10 Min (lb/100 ft²) 10 11 9 9 9 10 8 9PV (cP) 9 13 10 13 16 17 15 15 YP (lb/100 ft²) 21 19 22 16 20 23 19 20

TABLE 3 Monovalent RDF Formulations 1 2 3 4 Density (ppg) 9.5 9.5 10.310.3 Brine Type NaBr NaCl NaBr NaCl Base Brine Density (ppg) 8.68 8.689.54 9.54 Components (ppb) 12.4 NaBr 45.0 — 134.0 — NaCl — 21.0 — 75.0water 299.0 318.0 232.0 299.0 modified starch 10.0 10.0 10.0 10.0 metaloxide #1 2.0 2.0 2.0 2.0 metal oxide #2 2.0 2.0 0.50 0.50 metal oxide #24.0 4.0 2.0 2.0 SAFE-CARB 40 45.0 45.0 45.0 —

TABLE 4 Rheological Properties of monovalent brine-based RDFs Sample No.1 2 3 4 Aging Time Initial 16 h Initial 16 h Initial 16 h Initial 16 hAging Temp. (° F.) 180 Aging Mode Dynamic Dynamic Dynamic DynamicMeasurement Temp. (° F.) 120 600 RPM 43 53 37 42 40 45 37 40 300 RPM 3544 30 36 28 33 27 28 200 RPM 30 39 27 33 24 27 22 24 100 RPM 25 32 22 2718 20 18 18  6 RPM 14 15 12 14 9 9 9 8  3 RPM 13 14 11 13 7 8 8 7 Gel 10Sec (lb/100 ft²) 14 13 11 13 8 9 8 8 Gel 10 Sec (lb/100 ft²) 14 15 12 139 10 9 9 PV (cP) 8 9  7 6 12 12 10 12 YP (lb/100 ft²) 27 35  23q 30 1621 17 16

Example 2A Monovalent RDF Formulation

In the following example, monovalent RDF formulations are prepared andcharacterized. As shown below in Table 5, components were combined toproduce a water-based RDF having a final density of 13.5 lb/gal,components including metal oxide #1, which is a highly reactive metaloxide; a phosphonic acid scale inhibitor; and a chemically modifiedstarch; all of which are commercially available from M-I L.L.C.

TABLE 5 Monovalent RDF formulations tested in Example 2 Sample No. 5 6 7Component g/L g/L g/L 9.67 ppg NaCl/KCl brine 346.62 339.37 339.37 Water15.94 32.38 32.38 DITROL 10 10 10 metal oxide #1 2 2 2 metal oxide #20.5 1.5 1.5 metal oxide #3 2 2 2 polyglycol 10.50 — 3.5 sized CaCO₃ 2 11 1 sized CaCO₃ 10 — — 2 sized CaCO₃ 20 — — 2 sized CaCO₃ 40 38 38 35sized CaCO₃ 250 6 6 5

Following the preparation of the wellbore fluid formulations, therheology of the sample fluids was studied, both after initialformulation and after 16 hours of dynamic aging by “hot rolling.”Rheological properties were measured using a Fann 35 rheometer as shownin Table 6, and separately with a Brookfield rheometer as shown in Table7.

TABLE 6 Rheological properties of RDF formulations Sample No. 5 6 7 HeatAging Temp., F. — 225 — 225 — 225 Heat Aging Hours 16 h Hot Initial roll(HR) Initial 16 h HR Initial 16 h HR Mud weight, ppg 10.3 10.3 10.3 pH10.0 8.9 9.8 9.1 9.9 — Fann 35 Rheology Temperature 120° F. 600 RPM 4244 48 54 45 49 300 RPM 30 32 38 44 35 39 200 RPM 25 27 34 38 31 34 100RPM 20 21 27 30 25 26  6 RPM 10 19 12 13 12 11  3 RPM 9 9 11 12 10 10Plastic Viscosity (cPo) 12 12 10 10 10 10 Yield Point (lb/100 ft²) 18 2028 34 25 29 10 sec (lb/100 ft²) 10 11 11 13 13 11 10 min (lb/100 ft²) 1615 16 16 15 14

TABLE 7 Brookfield Rheology Sample No. 5 6 7 Spindle No. S66 Temperature120° F. Heat Aging Hours Initial 16 hr Initial 16 hr Initial 16 hr LSRV1 (cPo) 55,788 48,890 68,386 40,992 61,998 45,495 LSRV 2 (cPo) 57,78838,292 41,691 40,992 36,592 28,394 LSRV 3 (cPo) 57,788 34,393 36,79227,298 29,494 21,195

Example 2B Filter Cake Removal

In the following example, filter cakes were generated using the RDFformulations characterized in Example 1, and assays were conducted tostudy the efficiency of filter cake removal. During the assay, wellborefluids were formulated as reservoir drill-in fluids (RDF) as shown inTable 5. The standard disk of 10, 20 and 35 microns were used asreferences to design the bridging solids blend for the RDF system. Itshould be noted that these disks have a measured porosity ofapproximately 50%, thus the fluid loss results should be regarded as“worst-case” scenario and any subsequent fluid loss evaluation thatmeets the specified target would exhibit equal if not better fluid lossin the field.

Breaker fluids were formulated as shown below in Table 8, whereD-STRUCTOR is acid generating ester, combined with chelating agents #1and #2, and A-272, a mixture of at least one of an alkylaylpyridiumquaternary, alkyl thiol, methanol, propan-2-ol and ethoxylated alcoholsurfactant utilized as an organic corrosion inhibitor in an acidicenvironment, all of which are commercially available from M-I L.L.C(Houston, Tex.).

TABLE 8 Breaker System Formulations Breaker A B C Component ppb ppb ppbD-STRUCTOR 60.0 — — chelating agent #1 115.0 115.0 — A-272 1.7 — — 12.5ppg NaBr 279.8 233.0 251.8 water 68.9 107.0 80.5 chelating agent #2 — —120.0

Four breaker tests were run on a filter cake built after four hours.Filter cakes generated from the test formulations were tested accordingto the following conditions: breaker test 1—a filter cake generated fromformulation 1 was soaked for 5 days in breaker A, followed by returnflow testing; breaker test 2—a filter cake generated from formulation 2was soaked in breaker A for 5 days prior to return flow testing; breakertest 3—a filter cake generated from formulation 3 was soaked in breakerB for 3 days prior to return flow testing; and breaker test 4—a filtercake generated from formulation 3 was soaked in breaker C for 3 daysprior to return flow testing.

A return flow test was conducted to determine the ability of theselected breaker fluids to disrupt and/or dissolve filter cakesgenerated by the monovalent RDFs. Prior to addition of the RDFs, aninitial production direction flow on OFITE Aloxite Filter Disks FAO-20was conducted at 1, 2, 3, 4 and 5 psi. Next, 4-hour filter cakes weregenerated for the respective wellbore fluids at 225° F./500 psi,followed by decanting the remaining wellbore fluid and adding ˜100 mL ofone of breaker formulations to the cell. The cell was then reassembledand a 100 psi differential was applied to the cell and the heat jacketwas set to 225° F. Breakthrough measurements were then conducted bypressuring the cell up to a 500 psi differential, the bottom valve stemwas opened, and the time until breakthrough was recorded. Oncebreakthrough occurred, the bottom valve was left open until 30 ml ofeffluent was collected or until 30 minutes of time had elapsed. After 30ml of effluent had been collected or 30 minutes of time had elapsed, thecell was closed and the pressure was reduced to 100 psi differential andmonitored over the specified time interval for the breaker test. Thefinal production direction flow-back test was then conducted at 1, 2, 3,4 and 5 psi. The flow percentages were recorded to compare theeffectiveness of each individual breaker formulation. The cells werethen disassembled and the residual filter cake/disk was then removed andexamined for complete degradation. Results from the return flow testingare shown below in Table 9. Visual inspection of all remaining filtercakes showed substantial degradation and disruption of the filter cakes.

TABLE 9 Final flow rate and return flow rate Final Flow Pres- Vol- FlowReturn Breaker sure, Time, ume, Rate, Flow, Test No. psi sec mL mL/sec %1 1 1.00 0 0 0 Formulation 5 2 41.81 202.0 4.8 75.8 Breaker A 3 31.81205.0 6.4 80.3 5 day soak 4 26.25 208.0 7.9 84.8 5 22.94 214.0 9.3 84.45 22.66 213.0 9.4 85.1 2 1 1.0 0 0 0 Formulation 6 2 168.13 200.0 1.218.7 Breaker A 3 124.35 200.0 1.6 20.0 5 day soak 4 106.44 200.0 1.920.1 5 21.54 217.0 10.1 91.2 5 21.72 215.0 9.9 89.6 3 1 120.0 60.0 0.513.4 Formulation 7 2 120.0 52.0 0.4 6.8 Breaker B 3 120.0 114.0 1.0 11.83 day soak 4 62.0 201.0 3.2 34.7 5 41.9 202.0 4.8 43.6 5 42.03 207.0 4.944.6 4 1 90.2 212.0 2.3 63.0 Formulation 7 2 37.25 205.0 5.5 86.4Breaker C 3 28.22 207.0 7.3 91.4 3 day soak 4 24.1 208.0 8.6 92.3 520.91 212.0 10.1 91.8 5 20.91 212.0 10.1 91.8

Wellbore fluids of the present disclosure may find particular use fordrilling through producing intervals of a formation, where it may beparticularly desirable to increase clean-up abilities, to maximizehydrocarbon recovery, or the like. In particular, the RDF of the presentdisclosure may be useful for drilling such target intervals based on therheological properties, ease of removal, flowback qualities (includingslight stimulation of well, increasing flowback), and compatibility withcompletion techniques. Further, rheological properties may include theviscosity at high shear values is sufficiently low to minimize pressuredrops during drilling and the gel and viscosity values at low shearvalues are sufficiently high to keep the cuttings in suspension when thefluid circulation is stopped, reducing the formation of deposits.

Although the preceding description has been described herein withreference to particular means, materials, and embodiments, it is notintended to be limited to the particulars disclosed herein; rather, itextends to all functionally equivalent structures, methods and uses,such as are within the scope of the appended claims.

What is claimed:
 1. A wellbore fluid, comprising: an aqueous base fluidcomprising a monovalent brine; a modified starch; and a metal oxide. 2.The wellbore fluid of claim 1, wherein the metal oxide is present at aconcentration ranging from 1 ppb to 8 ppb.
 3. The wellbore fluid ofclaim 1, wherein the modified starch of the wellbore fluid is within arange of 3 ppb to 18 ppb.
 4. The wellbore fluid of claim 1, wherein themodified starch is derived from at least one of etherification,esterification, crosslinking, or combinations thereof.
 5. The wellborefluid of claim 1, wherein the modified starch comprises amylase and/oramylopectin crosslinked with at least one of epichlorohydrin, phosphorusoxychloride, adipic-acetic anhydrides and sodium trimetaphosphate. 6.The wellbore fluid of claim 1, wherein the modified starch comprises atleast one of corn, wheat, rice, tapioca, sago, waxy maize, waxy rice,sorghum, potato, and pea as a starch source.
 7. The wellbore fluid ofclaim 1, wherein the monovalent brine comprises a bromate salt.
 8. Thewellbore fluid of claim 1, further comprising: bridging particles. 9.The wellbore fluid of claim 1, further comprising: at least one aminestabilizer.
 10. A method of drilling a subterranean well, the methodcomprising: drilling the subterranean well while circulating a wellborefluid in the subterranean well, wherein the wellbore fluid comprises: anaqueous base fluid comprising a monovalent brine; and a modified starch.11. The method of claim 10, wherein the wellbore fluid further comprisesa metal oxide present at a concentration ranging from 1 ppb to 8 ppb.12. The method of claim 10, wherein the modified starch of the wellborefluid is within a range of 3 ppb to 18 ppb.
 13. The method of claim 10,wherein the wellbore fluid is used to drill a producing interval of thewell.
 14. A method of reducing the loss of fluid out of a subterraneanwell, the method comprising: injecting into the subterranean well awellbore fluid comprising: an aqueous base fluid comprising a monovalentbrine; a modified starch; and a metal oxide.
 15. The method of claim 14,wherein the metal oxide is present at a concentration ranging from 1 ppbto 8 ppb.
 16. A method of completing a wellbore, the method comprising:drilling the wellbore with a wellbore fluid to form a filter cake on thewalls thereof, the wellbore fluid comprising: an aqueous base fluidcomprising a monovalent brine; and a modified starch; emplacing abreaker fluid into the wellbore; and shutting in the well for a periodof time sufficient to initiate breaking of the filter cake.
 17. Themethod of claim 16, wherein the wellbore fluid further comprises a metaloxide present at a concentration ranging from 1 ppb to 8 ppb.
 18. Themethod of claim 16, further comprising gravel packing at least oneinterval of the wellbore.
 19. The method of claim 16, furthercomprising: circulating a wash fluid through the wellbore prior toand/or after emplacing a breaker fluid.
 20. The method of claim 16,wherein the modified starch comprises at least one of corn, wheat, rice,tapioca, sago, waxy maize, waxy rice, sorghum, potato, and pea as astarch source.